1. Field of Invention
The present invention relates generally to the small-scale simulation of oil-water separators, such as free water knockouts, heater treaters, and desalters, which are used in the production or processing of petroleum oil. More particularly, the present invention relates to methods for testing so-called thermal production.
2. Background and Related Art
Produced hydrocarbon fluids, such as crude oil and bitumen, naturally contain a variety of immiscible contaminants, such as water, salts, and solids, which have detrimental effects on transport lines and process equipment. The types and amounts of these contaminants vary depending on the particular hydrocarbon fluid. Additionally, water produced with the liquid hydrocarbon fluid, whether native, added, or condensed from steam added to the reservoir, also naturally contains a variety of immiscible contaminants, such as oil, organic solids and inorganic solids, which have detrimental effects on productive use or discharge of the water. The types and amounts of these contaminants vary depending on the particular produced water. Natural or synthetic emulsion stabilizers, such as asphaltenes, naphthenic acid salts, petroleum resins, bi-wet solids, drilling fluids, and the like, can keep the oil and water phases emulsified with each other.
Demulsifying, separating, and purifying these phases are necessary steps before further processing. These processes involve a variety of agitations and stratifications by fluid density for various lengths of time. A variety of diluents, wash fluids, and/or chemicals agents can be added to either or both phases in order to accelerate the process or improve the quality of the processed fluids. High voltage electric fields can be applied to the oil phase to accelerate and improve dehydration. Secondary filtration can be applied to the water phase to accelerate and improve clarification. Concentrated emulsion can be withdrawn from the stratified mesophase or “rag layer” between the two phases in a separator and centrifuged to accelerate and improve the separation. In all these processes, heat is generally added to raise the temperature of the fluids and reduce the viscosity of the fluids. For heavy crudes, oils and bitumens, the temperature is often raised above the boiling point of the water or of the light ends in a diluent added to the oil. This requires elevated pressures to keep the fluids liquid.
Chemical agents that may be added to accelerate and improve removal of water and solids from the hydrocarbon phase are generally known as demulsifiers, emulsion breakers, obverse emulsion breakers, dehydrators, water droppers, solids wetters, or dehazers (for clear fuels). These chemical agents can be added to the oil or to the water that is in contact with the oil. Chemical agents that may be added to accelerate and improve removal of oil and solids from the water phase are generally known as water clarifiers, reverse breakers, reverse emulsion breakers, deoilers, flocculants, coagulants, oil coalescers, or solids wetters. These chemical agents may be added to the water or, in some cases, to the oil that is in contact with the water. Chemical agents that are used to resolve a rag emulsion are often called sluggers, slop treaters, or interface clarifiers. Chemical agents that are used to prevent deposition of solids on surfaces are generally known as dispersants, deposit inhibiters, or antifoulants.
New chemical agents are typically selected and developed using a simple apparatus, such as a set of glass bottles or tubes, and a process referred to as “bottle testing”. In the simplest embodiment, emulsion samples and chemical agents are added to the bottles and shaken. The temperature is limited to about 90° C. at atmospheric pressure to keep the water from boiling. The rate of oil-water separation is monitored as a function of time by observing the amount of “free” water that collects at the bottom of the bottle and/or the amount of “free” oil that collects at the top of the bottle, the apparent purity of those phases—the “brightness” of the oil and the “clarity” of the water—and the amount, phase continuity, and coarseness of the emulsion in between the free water and the free oil. Because of the large number of possible chemical agents and combinations of these chemical agents that must be tested to find an appropriate treatment solution, and the unstable nature of the fresh emulsion samples used, the bottle testing needs to be carried out on many samples at once.
The foregoing bottle testing method has proven useful, but does not adequately simulate what happens at the higher temperatures and pressures used to process heavy crudes and bitumens. It has been shown that the surface active agents used for phase separation, as well as those native to the produced oil and water, behave differently at different temperatures.
The process of steam enhanced oil recovery or steam assisted gravity drainage (SAGD) of bitumen is particularly difficult and important to simulate. In an SAGD process, steam is injected into an underground reservoir at temperatures up to 260° C. The steam heats the oil as it condenses to high temperature water and carries the oil or bitumen out of the reservoir as an emulsion at temperatures up to 160° C. under pressures from 100 to 300 psig. A pressure of at least 75 psig is needed to keep water liquid at 160° C. The oil and water mix in highly turbulent flow at this temperature for several minutes to a few hours, then, after cooling to about 130° C., are separated in a series of vessels in which hydrocarbon diluent is added and water is removed. A variety of chemical separation aids are added at various places along oil/gas field production lines and ahead of equipment and vessels.
More sophisticated testing methods using stirred pressure vessels have been used to simulate the temperature and pressure of the separation process, but standard metal vessels do not allow critical visual observations to be made as the fluids separate. Glass, hot oil jacketed, pressure vessels can be used, but these are bulky and expensive to acquire, set up, and control—not amenable to testing many treatments at once in an oilfield environment.
Moreover, test results are highly dependent on the surface properties of small scale test vessels, due to the disproportionate amount of surface area to fluid volume. For example, water can bead-up on the glass around the oil phase instead of sheeting down into the water phase, making it impossible to measure. And the cationic polymers commonly used to separate oil from water irreversibly adsorb onto the anionic glass surfaces, changing the surface wetting for the next test. These polymers must be burned off, chemically or physically, or a layer of glass etched away. This can be difficult and dangerous to do on jacketed glass vessels, especially in the field, and can damage the integrity of the vessel at pressure.